In oil and gas exploration and production, wells are drilled in order to access the oil and gas trapped in rock formations below the surface of the Earth. A well typically consists of a borehole or wellbore (i.e., the hole drilled by the drill bit). The wellbore is lined with casing. A tubing string is inserted into the wellbore. The area between the tubing string and the casing is referred to as the annulus. A well may have one or more production zones capable of producing oil and/or gas corresponding to the various locations of the trapped oil and gas. The casing in the area of a production zone is perforated to allow oil and/or gas to flow into the annulus. Communication between the annulus and the tubing string is opened in the production zone to allow oil and/or gas to flow into the tubing string, then up to the surface. The flow of oil or gas, or rate of production, is generally determined by the size of the opening in the tubing string and the downhole pressure. Well control refers to controlling the flow of fluids and gas in the well and is extremely important as explained below.
Oil and gas is be trapped between various formations and is typically under tremendous pressure. That pressure is often more than sufficient to bring the oil and gas to the surface of the well and must be controlled. Often a well must be sealed-off or killed. For example, this is done to service downhole equipment. The well is killed by pumping in kill fluids, e.g., brine water or mud, such that the hydrostatic weight of the kill fluid creates sufficient pressure to exceed the pressure exerted by the trapped oil and gas. Where the pressure is relative low, brine water may be sufficient to control the well. However, when the pressure is relatively high, high-density mud is typically required to control the well. The pressure in the well changes over time. Often a well will require the use of different types of kill fluids over its life. To safely kill the well and prevent a blowout, the entire well must be filled with kill fluid, including the tubing string and the annulus. Conversely, the kill fluid must be removed from the tubing string once production resumes.
Conventionally, kill fluid was either pumped down the tubing string, then out the end of the tubing string, and up the annulus portion of the wellbore. Alternatively, kill fluid could be pumped down the annulus, then back up the tubing string. However, such operations could damage sensitive components attached to the end of the tube string. Moreover, certain equipment attached to the end of the tube string, such as an electronic submersible pump (ESP), prevented the flow of the heavy kill fluid between the tubing string and the annulus. Where an ESP was connected to the end of the tubing string, often the ESP itself was used to circulate the heavy kill fluid. But, ESPs were not designed for pumping heavy kill fluids and the increased wear and tear led them to fail prematurely.
One conventional method used a sliding sleeve to allow fluids to flow between the tubing string and the annulus, which were installed near the downhole-end of the tube string. The sliding sleeve could be shifted or slid between an open and closed position using wire-line tools. However, conventional sliding sleeves had many drawbacks, which were exacerbated by the harsh conditions in which they operated. The sleeves frequently failed to fully-open or fully-close, thus ending up in a partially-open or partially-closed position. They also frequently became stuck or locked shortly after being installed in the well. To make matters worse, there was no way to determine whether the sleeve was in the fully-open/closed position or in a partially-open/closed position. This further complicated matters as pressure tests on the tubing string could not be performed as it could not be determined whether a leak was present in the tubing string or the sleeve. The sleeves still further were susceptible to tearing in half. A large amount of material had to be removed from the sleeves to create communication ports through which fluid passed. The minimal material remaining in the area of the communication ports was susceptible to wear from the high pressure fluids and debris being pumped through the communication ports. This left the sleeve vulnerable to shearing in half when the tubing string was pulled. Finally, the sleeves were extremely large and expensive to manufacture due to their size and complex design. Such problems are exacerbated when a well had multiple production zones, which each required a sliding sleeve.
Over time as oil and gas is removed from a formation, the flow of oil and gas becomes diminished and wells start to dry-up. In order to increase recovery, a number of techniques may be employed to continue production. For example, water or gas may be injected into certain wells (called injection wells) in order to force the remaining oil and gas towards nearby production wells. Again, control over the delivery of such fluids and gases is critically important.
A need therefore exists for a more reliable system of well control which is easily operated, resistant to damage, and not subject to time-consuming periods of waiting due to low confidence in downhole position. Further there is a need for a well control tool for controlling one or more production zones. Still further there is a need for a well control tool that can work in both injection wells and production wells. Still further there is a need for a well control tool that is capable of receiving other tools, such as a pressure gauge.